Since water, oil and gas wells are generally lined with one or more metal casing strings adhered to the formation surrounding the wellbore by hardened cement, it is advantageous to perform quality inspections of the materials used to construct the well in order to ensure long-term operability of the well. Such materials include, but are not limited to, the geological formations themselves, the casings and the cements.
Such quality inspections include, but are not limited to, measuring the thickness or density to discover any texture characteristics and structural defects such as mechanical flaws, inhomogeneities in the materials, incomplete or missing materials, damage caused by geological or subsurface movement, time varying modification of the strata behind the casings due to fluid migration, and/or corrosion of materials.
Furthermore, wells can be fractured so that they release trapped hydrocarbons into the borehole and can be produced at the surface; in this case the reservoir rock is fractured by the operator by pumping specially designed fluids into the well at pressures high enough to make fissile subsurface rocks crack along fault lines. The effectiveness of this approach is critically dependent upon the fracture aperture and the lateral extent of the fracture. A means to geometrically characterize the fracture system, as well as a measurement of in situ stresses in the formation, are therefore important in predicting and measuring the propagation and extent of the fracture into the reservoir.
There are currently several non-destructive methods of well inspection available to operators, viz.:                1. Mechanical means, such as in-bore multi-fingered calipers;        2. In-bore optical camera methods;        3. Near-bore ultrasonic imaging methods;        4. Far-bore ultrasonic imaging methods;        5. Sonic logging methods to determine cement bond quality;        6. Electromagnetic methods to evaluate corrosion and well integrity; and        7. Electrical imaging methods used to determine the borehole shape, and to create a resistivity map of the borehole wall that can identify geological features as well as fractures in the reservoir rock.        
The mechanical means, such as the caliper, and the optical camera only produce information pertaining to the physical inner surface of the inner-most casing of the well, and are therefore incapable of offering operators information regarding the status of materials outside of the inner surface, such as the cement bond or volume.
Near-bore ultrasonic imaging methods, such as rotating single ultrasonic transducers, rely upon a method of emitting ultrasonic pulses in the frequency range of 100 to 800 kHz, and then receiving and measuring waveforms that have been reflected from the inner and outer surface of the inner-most casing.
The rate of decay of the waveforms indicates the quality of the cement bond to the outer surface of the inner-most casing, and can detect features as small as 2-3 centimeters in size. The resonant frequency of the casing provides information on the wall thickness of the casing. However, this ultrasonic method cannot be used to determine the structure of materials outside of the cement-casing interface.
Far-bore ultrasonic imaging methods rely on multiple panoramic ultrasonic transducers and imagers that compare received waveforms reflected from surfaces or interfaces of rapid density changes to inversion models of the wellbore structures created prior to the operation. In order to solve the time-of-flight inversion needed to resolve the ultrasonic data into image data (which contains radial distance data), the operator must create three-dimensional models of the wellbore apparatus prior to performing a data-collection operation. Thus, the operator effectively needs to know what an anomaly looks like and where it is located in advance in order to obtain a satisfactory image of the anomaly. Moreover, since the method is based upon reflected waveforms obtained from density-change interfaces, it is incapable of producing meaningful data regarding the nature of the cement bond or any cement volume discrepancies.
When a sonic logging method is used, a wire line tool is run in the borehole to detect how well the cement is bonded to the casing and formation via a principle based on resonance. Casing that is not bound has a higher resonant vibration than casing that is bound, which causes the energy from the sonic signal to be transferred to the formation. While this effect serves to detect a poor cement bond for normal cement, it fails to distinguish between an acceptable bond and a poor bond when low acoustic impedance cements are used, for example as is usually the case in deep water wells. In such instances, all casing appears to be poorly bonded.
Another disadvantage of the method is that the measurement is averaged azimuthally around the borehole and therefore cannot identify the orientation of any breach in the cement bond. Finally, it should be noted that this method can detect bond anomalies only on the order of 25 cm or greater along the longitudinal borehole axis, while vital breaches in the cement bond with smaller dimensions often occur.
There are two common electromagnetic methods used to evaluate the integrity of the tubing or casing. First, an eddy current device can be used to measure the presence of pits and holes in the inner wall of a casing. In the best practice of this method, the eddy-current measurement is used in conjunction with a flux-leakage measurement to determine casing corrosion, the latter being sensitive to defects on both the inner and outer walls. A transmitter coil produces a high frequency, alternating current magnetic field that induces eddy currents in the casing wall. These currents generate their own magnetic field, which induces a signal in two closely-spaced receiver coils. In smooth casing, these signals are the same, but if the inner wall is pitted, the signals are different.
Second, in a borehole within which a tubing or casing is installed, a low frequency electromagnetic wave propagation directly affected by the thickness of metal of the tubular in which it lies is transmitted and sensed within a borehole by a logging tool. The transmitted electromagnetic wave travels radially through the well-fluid before permeating through the tubing wall to the area outside.
The wave then propagates along the length of the tubing before re-entering the pipe, at which point it is measured by an array of detector antennae within the logging tool. As the wave propagates through the metal wall of the tubular its velocity and amplitude are reduced, however, the wave is unaffected by well fluid or formation properties. The transmitter-detector transit time and the amplitude of the electromagnetic wave are measured by the tool, and in turn are used to derive wall thickness.
These two techniques are often combined in a single borehole tool so that the measurements are made in the same run in the well. While this method provides an average wall thickness or detects anomalies on the inner and outer surfaces for the first tubing or casing in a well, it cannot make any measurements of a second casing or tubing in the same well. Moreover, while multiple pads deployed to detect anomalies provide azimuthal information regarding the presence of pits or holes in the casing, full circumferential coverage of the tubing or casing wall cannot be achieved.
Finally, in open boreholes assessed prior to being cased, an electrical current can be injected into the reservoir rock by a logging tool and sensed by a plurality of electrodes; in this event the electrodes are typically arranged to form an array disposed substantially perpendicular to the axis of the tool and deployed on mechanical pads pressed against the borehole wall. As the tool moves up the borehole wall, the sensed current in each of the plurality of electrodes varies in proportion to the local conductivity of the reservoir rock.
A current reading obtained from each sensing electrode is then displayed as an image spanning the circumference of the borehole as the tool moves vertically within the hole. Since the borehole fluid is more conductive than the rock formation, any fluid which fills a fracture that intersects the borehole results in a relatively higher current, with the current increasing in value in proportion to the aperture of the fracture, thus evaluating the effectiveness of the fracture in enhancing the production of hydrocarbons from the reservoir rock. In addition to the measurement of the currents, the tool measures the dimensions of the borehole in two perpendicular directions, thereby indicating the direction and magnitude of the elongation of the borehole and enabling a derivation of the in situ stress in the reservoir. This final measurement may be combined with the fracture evaluation to model the extent of the fracture in the reservoir rock.
While the measurement is made on multiple arms and pads attached to the tool, it does not provide full circumferential coverage of the borehole wall. Moreover, the determination of the aperture relies on accurate measurements of the rock resistivity and the resistivity of the borehole fluid. Finally, the aperture determination fails to provide meaningful information regarding how the aperture varies in magnitude as well as direction as it extends into the formation and therefore provides limited information about the fracture network.
In sum, there are no currently known technologies available to operators to permit detailed three-dimensional imaging of wellbore casings and the structures within and surrounding the wellbore, which offer information obtained from the inner surface or the inner-most casing, through multiple casings and annuli to a volume including the cement and geological formations. There is similarly a lack of technologies that permit the detailed three-dimensional imaging of the near-well environment just outside the borehole.
The invention comprises a method to measure the discrete structures within and immediately surrounding a borehole and to recreate said structures as a three-dimensional representation through mathematical reconstructions of x-ray backscattered volume imaging. These methods are further embodied by means that may be used to practice the method for use in a water, oil or gas well.
In conventional, non-destructive three-dimensional imaging methods based upon x-ray technology, an operator acquires x-ray attenuation data in wedges through a sample by moving an x-ray source and electronic imaging device arranged on opposite sides of a sample around the outside of the sample. Mathematical processing, typically Radon transform or computational processing, via various algorithms, is applied to each data slice to create a three-dimensional reconstruction of the sample. The resulting reconstructions are typically displayed as two-dimensional slice images, though the underlying data actually represent volumetric properties of the sample. Various visualization techniques that better represent the three-dimensional quality of the data are becoming more prevalent.
In addition to x-ray computed tomography scans (CT), tomograms are currently derived using several other physical phenomena such as gamma rays in single-photon emission computed tomography scans (SPECT), radio-waves in magnetic resonance imaging (MRI), electrons in transmission electron microscopy (TEM), and electron-positron annihilation in positron emission tomography (PET). However, all tomograms are derived from an outside-in perspective, wherein the radiation source and/or imaging device are located on the outside or around the sample to be imaged.
The prior art teaches a variety of techniques that use x-rays or other radiant energy to inspect or obtain information about the structures within or surrounding the borehole of a water, oil or gas well, though none teach any type of inside-out volume imaging technique as described and claimed later in this application.
For example, U.S. Pat. No. 3,564,251 to Youmans discloses the use of a radially scanning collimated x-ray beam used to produce an attenuated signal at a detector for the purpose of producing a spiral-formed log of the inside of a casing or borehole surface immediately surrounding the tool.
U.S. Pat. No. 7,675,029 to Teague et al. provides an apparatus that permits the measurement of x-ray backscattered photons from any horizontal surface inside of a borehole that refers to two-dimensional imaging techniques.
U.S. Pat. No. 7,634,059 to Wraight discloses an apparatus that may be used to measure two-dimensional x-ray images of the inner surface inside of a borehole, but lacks the ability to look inside of the borehole in a radial direction.
U.S. Pat. No. 8,481,919 to Teague teaches a method of producing high-energy photon radiation in a borehole without the use of radioactive isotopes, and further describes rotating collimators disposed around a fixed source installed internally within the apparatus, but does not have rotatable solid-state detectors with collimators. It further teaches the use of conical and radially symmetrical anode arrangements that permit the production of panoramic x-ray radiation.
US 2013/0009049 by Smaardyk discloses an apparatus that allows measurement of backscattered x-rays from the inner layers of a borehole, but lacks the ability to reconstruct a three-dimensional representation.
U.S. Pat. No. 8,138,471 to Shedlock discloses a scanning-beam apparatus based on an x-ray source, a rotatable x-ray beam collimator, and solid-state radiation detectors that enable the imaging of only the inner surfaces of borehole casings and pipelines.
U.S. Pat. No. 5,326,970 to Bayless discloses a tool that measures backscattered x-rays from inner surfaces of a borehole casing with the x-ray source being based on a linear accelerator.
U.S. Pat. No. 7,705,294 to Teague et al. teaches an apparatus that measures backscattered x-rays from the inner layers of a borehole in selected radial directions with the missing segment data being populated through movement of the apparatus through the borehole. The apparatus permits generation of data for a two-dimensional reconstruction of the well or borehole, but does not disclose the geometry needed for illuminating an x-ray beam so as to permit discrimination of the depth from which the backscattered photons originated, rather it only discloses the direction.
U.S. Pat. No. 5,081,611 to Hornby discloses a method of back projection to determine acoustic physical parameters of the earth formation longitudinally along the borehole using a single ultrasonic transducer and a number of receivers, which are typically distributed along the primary axis of the tool.
U.S. Pat. No. 6,725,161 to Hillis et al. discloses a method of placing a transmitter in a borehole, and a receiver on the surface of the earth, or perhaps a receiver in a borehole and a transmitter on the surface of the earth, in order to determine structural information regarding the geological materials between the transmitter and receiver.
U.S. Pat. No. 6,876,721 to Siddiqui discloses a method of correlating information derived from a core-sample with information obtained from a borehole density log. The core-sample information is derived from a CT scan of the core-sample, whereby the x-ray source and detectors are located on the outside of the sample and thereby configured as an outside-looking-in arrangement. Various types of information derived from the CT scan, e.g., bulk density, is then compared to and correlated with the log information.
U.S. Pat. No. 4,464,569 to Flaum discloses a method of determining the elemental composition of earth formations surrounding a well borehole using detected neutron capture gamma radiation emanating from the earth formation following neutron irradiation of the earth formation by a neutron spectroscopy logging tool.
U.S. Pat. No. 4,433,240 to Seeman discloses a borehole logging tool that detects natural radiation obtained from the rock of the formation and logs that information so that it may be represented in an intensity versus depth plot format.
U.S. Pat. No. 3,976,879 to Turcotte discloses a borehole logging tool that detects and records backscattered radiation obtained from the formation surrounding the borehole by means of a pulsed electromagnetic energy or photon source, so that characteristic information can be represented in an intensity versus depth plot format.
U.S. Pat. No. 4,883,956 to Manente et al. discloses an apparatus and method for investigation of subsurface earth formations using an apparatus adapted for movement through a borehole. Depending upon the formation characteristic or characteristics to be measured, the apparatus may also include a natural or artificial radiation source for irradiating the formations with penetrating radiation such as gamma rays, x-rays or neutrons. The light produced by a scintillator in response to detected radiation is then used to generate a signal representative of at least one characteristic of the radiation, and this signal is recorded.
U.S. Pat. No. 6,078,867 to Plumb et al. discloses a method for generating a three-dimensional graphical representation of a borehole by, for example, receiving caliper data relating to the borehole, generating a three-dimensional wire mesh model of the borehole from the caliper data, and color mapping the three-dimensional wire mesh model from the caliper data based on either borehole form, rugosity and/or lithology.
U.S. Pat. No. 3,321,627 to Tittle discloses a system having collimated detectors and collimated gamma-ray sources used to determine the density of a formation outside of a borehole so that it can be represented in a density versus depth plot format.
There is, therefore, a long-felt need that remains unmet despite many prior unsuccessful attempts to achieve a volume image derived from an inside-out perspective, wherein the radiation source and imaging device are both located within the sample, in a manner that overcomes the various shortcomings of the prior art.